Process and apparatus for hydrocracking a residue stream in two stages with aromatic saturation

ABSTRACT

A process and apparatus for two stage hydrocracking of resid feed saturates aromatics including PNA&#39;s from the first stage hydrocracking unit to prevent production of HPNA&#39;s. The saturated aromatics including PNA&#39;s can be hydrocracked in the second stage to minimize or eliminate purged unconverted oil to approach or obtain maximum conversion. In an aspect, a separator and a first hydrocracking reactor may be located in the same vessel.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority from Provisional Application No.62/439,318 filed Dec. 27, 2016, the contents of which cited applicationare hereby incorporated by reference in its entirety.

FIELD

The field is the hydrocracking of hydrocarbon streams, particularlytwo-stage hydrocracking and saturation of hydrocarbon streams.

BACKGROUND

Hydroprocessing can include processes which convert hydrocarbons in thepresence of hydroprocessing catalyst and hydrogen to more valuableproducts. Hydrocracking is a hydroprocessing process in whichhydrocarbons crack in the presence of hydrogen and hydrocrackingcatalyst to lower molecular weight hydrocarbons. Depending on thedesired output, a hydrocracking unit may contain one or more fixed bedsof the same or different catalyst.

Two-stage hydrocracking processes involve fractionation of ahydrocracked stream from a first stage hydrocracking reactor followed byhydrocracking of an unconverted oil (UCO) stream in a second stagehydrocracking reactor. However, the best two-stage hydrocracking processcannot achieve full conversion to materials boiling below the diesel cutpoint. Typically, a bottoms stream from the fractionation column intwo-stage hydrocracking comprises a recycle oil (RO) stream and an UCOstream. The RO is recycled to the second stage hydrocracking reactorwhile the UCO is purged from the process to remove unconvertible heavypolynuclear aromatics (HPNA's) from the process. HPNA's are fusedaromatic rings comprising more than eight rings. HPNA's in RO and UCOcan cause significant adverse impact on hydrocracking operations such asfouling of the exchangers and coking on the catalyst. Several processesare available to manage HPNA rejection, such as steam stripping andadsorption

Hydrotreating is a process in which hydrogen is contacted with ahydrocarbon stream in the presence of hydrotreating catalysts which areprimarily active for the removal of heteroatoms, such as sulfur,nitrogen and metals, such as iron, nickel, and vanadium from thehydrocarbon feedstock. In hydrotreating, hydrocarbons with double andtriple bonds may be saturated. Aromatics may also be saturated. Somehydrotreating processes are specifically designed to saturate aromatics.Resid hydrotreating is a hydrotreating process to remove metals, sulfurand nitrogen from an atmospheric or vacuum resid (VR) feed, so that itcan be cracked to valuable fuel products.

Global crude oil consumption continues to increase especially in thedeveloping countries and fuel specifications also continue to tighten.The outlets for residue fuel oil are decreasing, while the availabilityof heavy, sour crudes are increasing. The gas oil fraction of theatmospheric residue (AR) can be processed by hydrocracking to producediesel fuels while the VR fraction can be converted into distillatefuels by a primary upgrading process such as slurry hydrocracking.

It would be highly desirable to have a combined solution to process theentire AR stream.

BRIEF SUMMARY

A process and apparatus for two stage hydrocracking of a resid feedstream involves the saturation of aromatics including PNA's from thefirst stage hydrocracking unit to prevent formation of HPNA's in thesecond stage hydrocracking unit. The saturated PNA's can be hydrocrackedin the second stage to minimize or eliminate purged unconverted oil toapproach or obtain maximum conversion. In an aspect, a separator may beused to flash gas from hydrotreated resid fed to the first stagehydrocracking reactor. The separator and the first stage hydrocrackingreactor may be located in the same vessel.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic drawing of a two-stage hydrocracking unit.

FIG. 2 is a schematic drawing of an alternative two-stage hydrocrackingunit.

DEFINITIONS

The term “communication” means that material flow is operativelypermitted between enumerated components.

The term “downstream communication” means that at least a portion ofmaterial flowing to the subject in downstream communication mayoperatively flow from the object with which it communicates.

The term “upstream communication” means that at least a portion of thematerial flowing from the subject in upstream communication mayoperatively flow to the object with which it communicates.

The term “direct communication” means that flow from the upstreamcomponent enters the downstream component without undergoing acompositional change due to physical fractionation or chemicalconversion.

The term “column” means a distillation column or columns for separatingone or more components of different volatilities. Unless otherwiseindicated, each column includes a condenser on an overhead of the columnto condense and reflux a portion of an overhead stream back to the topof the column and a reboiler at a bottom of the column to vaporize andsend a portion of a bottoms stream back to the bottom of the column.Absorber and scrubbing columns do not include a condenser on an overheadof the column to condense and reflux a portion of an overhead streamback to the top of the column and a reboiler at a bottom of the columnto vaporize and send a portion of a bottoms stream back to the bottom ofthe column. Feeds to the columns may be preheated. The overhead pressureis the pressure of the overhead vapor at the vapor outlet of the column.The bottom temperature is the liquid bottom outlet temperature. Overheadlines and bottoms lines refer to the net lines from the columndownstream of any reflux or reboil to the column unless otherwiseindicated. Stripping columns omit a reboiler at a bottom of the columnand instead provide heating requirements and separation impetus from afluidized inert vaporous media such as steam.

As used herein, the term “True Boiling Point” (TBP) means a test methodfor determining the boiling point of a material which corresponds toASTM D-2892 for the production of a liquefied gas, distillate fractions,and residuum of standardized quality on which analytical data can beobtained, and the determination of yields of the above fractions by bothmass and volume from which a graph of temperature versus mass %distilled is produced using fifteen theoretical plates in a column witha 5:1 reflux ratio.

As used herein, the term “initial boiling point” (IBP) means thetemperature at which the sample begins to boil using ASTM D-6352.

As used herein, the term “T5”, “T70” or “T95” means the temperature atwhich 5 mass percent, 70 mass percent or 95 mass percent, as the casemay be, respectively, of the sample boils using ASTM D-6352.

As used herein, the term “diesel cut point” is between about 343° C.(650° F.) and about 399° C. (750° F.) using the TBP distillation method.

As used herein, the term “diesel boiling range” means hydrocarbonsboiling in the range of between about 132° C. (270° F.) and the dieselcut point using the TBP distillation method.

As used herein, the term “separator” means a vessel which has an inletand at least an overhead vapor outlet and a bottoms liquid outlet andmay also have an aqueous stream outlet from a boot. A flash drum is atype of separator which may be in downstream communication with aseparator which latter may be operated at higher pressure.

As used herein, the term “polynuclear aromatics” (PNA) means an aromatichydrocarbon comprising more than three but less than eight rings fusedaromatic rings.

As used herein, the term “heavy polynuclear aromatics” (HPNA) means anaromatic hydrocarbon comprising eight or more fused aromatic rings.

DETAILED DESCRIPTION

The subject process and apparatus converts a resid feed stream intodistillate fuels through combination of resid hydrotreating and twostages of hydrocracking. In the second stage of hydrocracking, aromaticsincluding PNA's are substantially saturated to prevent HPNA formationand to minimize or eliminate a purge of unconverted oil (UCO), therebyimproving overall conversion and yields. Formation of HPNA's is mainlydue to condensation of polynuclear aromatics (PNA's) existing in RO.Saturation of PNA's in RO can reduce or eliminate HPNA formation in asecond stage of hydrocracking, which then results in reducing oreliminating the UCO purge.

The subject apparatus and process minimizes or eliminates UCO productionand HPNA management by integrating catalytic aromatics saturation in thesecond hydrocracking stage to enhance diesel yield selectivity andachieve near full conversion.

The apparatus and process 10 for hydrocracking a hydrocarbon streamcomprise a first stage hydrocracking unit 12, a fractionation section 14and a second stage hydrocracking unit 150. A resid hydrocarbon stream inresid line 18 and a first stage hydrogen stream in a first stagehydrogen line 22 are fed to the first stage hydrocracking unit 12.

In one aspect, the process and apparatus described herein areparticularly useful for hydrocracking a hydrocarbon feed streamcomprising a resid hydrocarbonaceous feedstock. A suitable resid feed isAR having an T5 between about 316° C. (600° F.) and about 399° C. (750°F.) and a T70 between about 510° C. (950° F.) and about 704° C. (1300°F.). VR having a T5 in the range between about 482° C. (900° F.) andabout 565° C. (1050° F.) may also be a suitable feed. VR, atmosphericgas oils having T5 between about 288° C. (550° F.) and about 315° C.(600° F.) and vacuum gas oils (VGO) having T5 between about 316° C.(600° F.) and about 399° C. (750° F.) may also be blended with the AR tomake a suitable resid feed. Deasphalted oil, visbreaker bottoms,clarified slurry oils, and shale oils may also be suitable resid feedsalone or by blending with AR or VR. Typically these resid feeds containsignificant concentration of metals which have to be removed before thehydrocracking process. Typically, suitable resid feeds include about 50to about 500 wppm metals but resid feeds with less than about 200 wppmmetals are preferred. Nickel, vanadium and iron are some of the typicalmetals in resid feeds.

A first hydrotreating hydrogen stream in a first hydrotreating hydrogenline 24 may split off from the first stage hydrogen line 22. The firsthydrotreating hydrogen stream may join the hydrocarbonaceous stream infeed line 18 to provide a first hydrocarbon feed stream in a firsthydrocarbon feed line 26. The first hydrocarbon feed stream in the firsthydrocarbon feed line 26 may be heated by heat exchange with a firsthydrocracked stream in first hydrocracked effluent line 48 and in afired heater. The heated first hydrocarbon feed stream in line 28 may befed to a first resid hydrotreating unit 30.

Hydrotreating is a process wherein hydrogen is contacted withhydrocarbon in the presence of hydrotreating catalysts which areprimarily active for the removal of heteroatoms, such as sulfur,nitrogen and metals from the hydrocarbon feedstock. In hydrotreating,hydrocarbons with double and triple bonds may be saturated. Aromaticsmay also be saturated. Some hydrotreating processes are specificallydesigned to saturate aromatics.

The first resid hydrotreating unit 30 may comprise three hydrotreatingreactors comprising a demetallizing reactor 34 and a desulfurizationreactor 36. In an aspect, the resid hydrotreating unit 30 comprises adenitrogenation reactor 38. More or less hydrotreating reactors may beused, and each hydrotreating reactor 34, 36, 38 may comprise a part of ahydrotreating reactor or comprise one or more hydrotreating reactors.Each hydrotreating reactor 34, 36, 38 may comprise part of a catalystbed or one or more catalyst beds in one or more hydrotreating reactorvessels 35. In FIG. 1, the first hydrotreating unit 30 comprises threereactors 34, 36 and 38 comprising three beds of hydrotreating catalystin a single hydrotreating reactor vessel 35. Moreover, multiple reactorsof each hydrotreating reactor 34, 36, 38 may be used. Multiple reactorsmay also include reactors operating in swing bed mode or in lead-lagmode.

Suitable hydrotreating catalysts for use in the first residhydrotreating unit are any known conventional hydrotreating catalystsand include those which are comprised of at least one Group VIII metal,preferably iron, cobalt and nickel, more preferably nickel and/or cobaltand at least one Group VI metal, preferably molybdenum and tungsten, ona high surface area support material, preferably alumina. It is withinthe scope of the present invention that more than one type ofhydrotreating catalyst be used in the same reaction vessel or catalystbed. The Group VIII metal is typically present in an amount ranging fromabout 1 to about 10 wt %, preferably from about 2 to about 5 wt %. TheGroup VI metal will typically be present in an amount ranging from about1 to about 20 wt %, preferably from about 2 to about 10 wt %.

The first hydrocarbon feed stream in line 28 may be fed to the firsthydrotreating reactor 34. The first hydrotreating reactor may comprise ademetallizing reactor 34. Water may be added to the resid feed in line28. In an embodiment, the first demetallizing reactor 34 may comprise ahydrodemetallization catalyst comprising cobalt and molybdenum on gammaalumina. The demetallization reactor is intended to demetallize theheated resid stream, so to reduce the metals concentration in the freshfeed stream by about 40 to about 100 wt % and typically about 65 toabout 95 wt % to produce a first demetallized effluent stream exitingthe demetallization reactor 34. The metal content of the demetallizedresid stream may be less than about 50 wppm and preferably between about1 and about 25 wppm. The demetallization reactor 34 may alsodenitrogenate and/or desulfurize the resid stream. A demetallizedeffluent stream reduced in metals concentration relative to the residstream may exit the first hydrotreating reactor 34 and enter the secondhydrotreating reactor 36 comprising a second denitrogenation reactor.

The first resid hydrotreating unit 30 may include a second hydrotreatingreactor 36. Demetallized effluent from the demetallization reactor 34 issupplemented with hydrotreating hydrogen from manifold 31 and fed to thesecond hydrotreating reactor 36. In an embodiment, the secondhydrotreating reactor 36 may comprise a desulfurization reactor thatincludes a hydrodesulfurization catalyst which may comprise nickel orcobalt and molybdenum on gamma alumina to convert organic sulfur tohydrogen sulfide. The desulfurization reactor reduces the sulfurconcentration in the resid feed stream by about 40 to about 100 wt % andtypically about 65 to about 95 wt % to produce a desulfurized effluentstream exiting the desulfurized reactor. In this embodiment, thedesulfurized effluent stream may exit the second hydrotreating reactor36 and enter the third hydrotreating reactor 38.

The first resid hydrotreating unit 30 may include a third hydrotreatingreactor 38. In an embodiment, desulfurized effluent from thedesulfurization reactor 36 is supplemented with hydrogen from manifold31 and fed the third hydrotreating reactor which may comprise adenitrogenation reactor 38 comprising a hydrodenitrogenation catalyst.The denitrogenation catalyst which may comprise nickel and molybdenum ongamma alumina to convert organic nitrogen to ammonia. Thehydrodenitrogenation catalyst may also be able to saturate aromatics tonaphthenes. The denitrogenation section reduces the nitrogenconcentration in the resid stream by about 40 to about 100 wt % andtypically about 65 to about 95 wt % to produce a denitrogenated effluentstream exiting the denitrogenation reactor 65. In this embodiment, thedenitrogenated effluent may exit the third hydrotreating reactor 38. Thedenitrogenation catalyst in the third hydrotreating reactor 38 may be adifferent and preferably more active than the desulfurization catalystin the second hydrotreating reactor 36. For example, the denitrogenationcatalyst may have a higher metals concentration than the desulfurizationcatalyst.

It is contemplated that in the first resid hydrotreating unit 30 one,two or all of the hydrotreating reactors 34, 36 and 38 optionallydemetallize and desulfurize the resid feed stream and optionally,demetallize, desulfurize and denitrogenate the resid feed stream inresid feed line 28. Preferably, the first hydrotreating unit 30comprises three hydrotreating reactors to demetallize, desulfurize anddenitrogenate the resid feed stream.

Supplemental hydrogen in a first hydrotreating supplemental hydrogenline 31 may be added at an interstage locations between hydrotreatingreactors 34, 36 and 38 in the first resid hydrotreating unit 30.

Preferred reaction conditions in each of the hydrotreating reactors 34,36 and 38 include a temperature from about 66° C. (151° F.) to about455° C. (850° F.), suitably 316° C. (600° F.) to about 427° C. (800° F.)and preferably 343° C. (650° F.) to about 399° C. (750° F.), a pressurefrom about 2.1 MPa (gauge) (300 psig) to about 27.6 MPa (gauge) (4000psig), preferably about 13.8 MPa (gauge) (2000 psig) to about 20.7 MPa(gauge) (3000 psig), a liquid hourly space velocity of the freshhydrocarbonaceous feedstock from about 0.1 hr⁻¹ to about 5 hr⁻¹,preferably from about 0.2 to about 2 hr⁻¹, and a hydrogen rate of about168 Nm³/m³ (1,000 scf/bbl) to about 1,680 Nm³/m³ oil (10,000 scf/bbl),preferably about 674 Nm³/m³ oil (4,000 scf/bbl) to about 1,011 Nm³/m³oil (6,000 scf/bbl).

A first hydrotreated resid stream that exits the first hydrotreatingunit 30 in a first hydrotreating effluent line 32 has a reducedconcentration of metals, sulfur and nitrogen relative to the residstream in line 28 and can be taken as a first hydrocracking feed stream.Hydrogen gas laden with ammonia and hydrogen sulfide may be removed fromthe first hydrocracking feed stream in a hydrocracking separator, butthe first hydrocracking feed stream may be fed directly to thehydrocracking reactor 40 without separation.

The first hydrotreated resid stream may be heated before entering afirst hydrocracking reactor 40 in the first hydrotreating effluent line32. The first hydrocracking reactor 40 may comprise a firsthydrocracking reactor vessel 40 v. The first hydrocracking reactor 40 isin downstream communication with the first hydrotreating unit 30. Thefirst hydrocracking reactor vessel 40 v may include a separator 72 abovethe first hydrocracking reactor 40 comprising one or more beds 42 ofhydrocracking catalyst. In an aspect, the separator 72 and the firsthydrocracking reactor 40 comprising the hydrocracking catalyst beds 42may be in the same hydrocracking reactor vessel 40 v.

In an aspect, the first hydrotreated resid stream enters the firsthydrocracking reactor 40 near a top of the reactor vessel 40 v and flowsinto the separator 72. The first hydrocracking separator is indownstream communication with the first hydrotreating unit 30. The firsthydrotreated resid stream is fed into the separator 72 at an inlet 72 ithat is located above a lower edge of a tubular baffle 74 that issecured to the top of the vessel 40 v. A first gas hydrotreated streamseparates from a first liquid hydrotreated resid stream of the firsthydrotreated resid stream and descends below and around the tubularbaffle 74 to separate from the first liquid hydrotreated resid stream.The gas first hydrotreated resid stream is removed from an outlet 46 oin the top of the hydrocracking reactor vessel 40 v located inwardly ofthe baffle 74 via a hydrocracking separator overhead line 46. The gasfirst hydrotreated resid stream may be admixed with a hot gaseous streamprovided via a hot separator overhead line 52 and the resulting admixedstream is carried via line 53 and introduced into a heat exchanger to becooled. A resulting cooled and partially condensed hot separator admixedstream is introduced into a cold separator 56. The gas firsthydrotreated resid stream removes with it a majority of the hydrogensulfide and ammonia that tend to deactivate hydrocracking catalyst.

The first liquid hydrotreated resid stream separated in the separator 72from the first hydrotreated resid stream flows downwardly onto a tray 76that may generate a liquid level, such as a chimney tray. The liquidlevel is maintained by a vertical, weir 78 which may be tubular in anaspect. A cap 80 which may be tubular also with a wider inner diameterthan the tubular weir 78 is superimposed over the weir. The tubular cap80 has a closed upper end that is opposed to an opening in the weir 78and the tray 76 to cooperatively prevent the direct, downward flow ofliquid and any flow of undissolved vapor downwardly past the tray 76into a mixing zone 82. The downwardly flowing first liquid hydrotreatedresid stream from tray 76 is admixed in the mixing zone 82 with a firsthydrocracking hydrogen stream from the first stage hydrogen line 22 fromhydrogen manifold 44 introduced into the mixing zone 82 below the tray76 and the separator 72. The liquid on the tray 76 and the downward flowof liquid prevents hydrogen from moving upwardly through the chimneytray to exit through the outlet 46 o.

The liquid first hydrotreated resid stream mixed with the firsthydrocracking hydrogen stream from manifold 44 is fed to a bed 42 ofhydrocracking catalyst in the first hydrocracking reactor 40 to behydrocracked.

Hydrocracking is a process in which hydrocarbons crack in the presenceof hydrogen to lower molecular weight hydrocarbons. The firsthydrocracking reactor 40 may be a fixed bed reactor that comprises oneor more vessels, single or multiple catalyst beds 42 in each vessel, andvarious combinations of hydrotreating catalyst, hydroisomerizationcatalyst and/or hydrocracking catalyst in one or more vessels. It iscontemplated that the first hydrocracking reactor 40 be operated in acontinuous liquid phase in which the volume of the liquid hydrocarbonfeed is greater than the volume of the hydrogen gas. The firsthydrocracking reactor 40 may also be operated in a conventionalcontinuous gas phase, a moving bed or a fluidized bed hydroprocessingreactor.

The first hydrocracking reactor 40 comprises a plurality of firsthydrocracking catalyst beds 42. The first or an upstream bed in thefirst hydrocracking reactor 40 may comprise a first hydrocrackingcatalyst bed 42. The first hydrocracking reactor is in downstreamcommunication with the hydrocracking separator 72.

The hydrotreated first hydrocracking feed stream is hydrocracked over afirst hydrocracking catalyst in the first hydrocracking catalyst beds 42in the presence of the first hydrocracking hydrogen stream from a firsthydrocracking hydrogen line 22 to provide a first hydrocracked stream.Subsequent catalyst beds 42 in the hydrocracking reactor may comprisehydrocracking catalyst over which additional hydrocracking occurs to thehydrocracked stream. Hydrogen manifold 44 may deliver supplementalhydrogen streams from the first hydrocracking hydrogen line 22 to one,some or each of the catalyst beds 42. In an aspect, the supplementalhydrogen is added to each of the catalyst beds 42 at an interstagelocation between adjacent beds, so supplemental hydrogen is mixed withhydroprocessed effluent exiting from the upstream catalyst bed 42 beforeentering the downstream catalyst bed 42.

The first hydrocracking reactor 40 may provide a total conversion of atleast about 20 vol % and typically greater than about 50 vol % of thefirst hydrocracking feed stream in the first hydrotreating effluent line32 to products boiling below the diesel cut point. The firsthydrocracking reactor 40 may operate at partial conversion of more thanabout 30 vol % or full conversion of at least about 90 vol % of the feedbased on total conversion. The first hydrocracking reactor 40 may beoperated at mild hydrocracking conditions which will provide about 20 toabout 60 vol %, preferably about 20 to about 50 vol %, total conversionof the hydrocarbon feed stream to product boiling below the diesel cutpoint.

The first hydrocracking catalyst may utilize amorphous silica-aluminabases or low-level zeolite bases combined with one or more Group VIII orGroup VIB metal hydrogenating components if mild hydrocracking isdesired to produce a balance of middle distillate and gasoline. Inanother aspect, when middle distillate is significantly preferred in theconverted product over gasoline production, partial or fullhydrocracking may be performed in the first hydrocracking reactor 40with a catalyst which comprises, in general, any crystalline zeolitecracking base upon which is deposited a Group VIII metal hydrogenatingcomponent. Additional hydrogenating components may be selected fromGroup VIB for incorporation with the zeolite base.

The zeolite cracking bases are sometimes referred to in the art asmolecular sieves and are usually composed of silica, alumina and one ormore exchangeable cations such as sodium, magnesium, calcium, rare earthmetals, etc. They are further characterized by crystal pores ofrelatively uniform diameter between about 4 and about 14 Angstroms(10⁻¹⁰ meters). It is preferred to employ zeolites having a relativelyhigh silica/alumina mole ratio between about 3 and about 12. Suitablezeolites found in nature include, for example, mordenite, stilbite,heulandite, ferrierite, dachiardite, chabazite, erionite and faujasite.Suitable synthetic zeolites include, for example, the B, X, Y and Lcrystal types, e.g., synthetic faujasite and mordenite. The preferredzeolites are those having crystal pore diameters between about 8 and 12Angstroms (10⁻¹⁰ meters), wherein the silica/alumina mole ratio is about4 to 6. One example of a zeolite falling in the preferred group issynthetic Y molecular sieve.

The natural occurring zeolites are normally found in a sodium form, analkaline earth metal form, or mixed forms. The synthetic zeolites arenearly always prepared first in the sodium form. In any case, for use asa cracking base it is preferred that most or all of the originalzeolitic monovalent metals be ion-exchanged with a polyvalent metaland/or with an ammonium salt followed by heating to decompose theammonium ions associated with the zeolite, leaving in their placehydrogen ions and/or exchange sites which have actually beendecationized by further removal of water. Hydrogen or “decationized” Yzeolites of this nature are more particularly described in U.S. Pat. No.3,100,006.

Mixed polyvalent metal-hydrogen zeolites may be prepared byion-exchanging first with an ammonium salt, then partially backexchanging with a polyvalent metal salt and then calcining. In somecases, as in the case of synthetic mordenite, the hydrogen forms can beprepared by direct acid treatment of the alkali metal zeolites. In oneaspect, the preferred cracking bases are those which are at least about10 wt %, and preferably at least about 20 wt %, metal-cation-deficient,based on the initial ion-exchange capacity. In another aspect, adesirable and stable class of zeolites is one wherein at least about 20wt % of the ion exchange capacity is satisfied by hydrogen ions.

The active metals employed in the preferred first hydrocrackingcatalysts of the present invention as hydrogenation components are thoseof Group VIII, i.e., iron, cobalt, nickel, ruthenium, rhodium,palladium, osmium, iridium and platinum. In addition to these metals,other promoters may also be employed in conjunction therewith, includingthe metals of Group VIB, e.g., molybdenum and tungsten. The amount ofhydrogenating metal in the catalyst can vary within wide ranges. Broadlyspeaking, any amount between about 0.05 wt % and about 30 wt % may beused. In the case of the noble metals, it is normally preferred to useabout 0.05 to about 2 wt % noble metal.

The method for incorporating the hydrogenation metal is to contact thebase material with an aqueous solution of a suitable compound of thedesired metal wherein the metal is present in a cationic form. Followingaddition of the selected hydrogenation metal or metals, the resultingcatalyst powder is then filtered, dried, pelleted with added lubricants,binders or the like if desired, and calcined in air at temperatures of,e.g., about 371° C. (700° F.) to about 648° C. (1200° F.) in order toactivate the catalyst and decompose ammonium ions. Alternatively, thebase component may first be pelleted, followed by the addition of thehydrogenation component and activation by calcining.

The foregoing catalysts may be employed in undiluted form, or thepowdered catalyst may be mixed and copelleted with other relatively lessactive catalysts, diluents or binders such as alumina, silica gel,silica-alumina cogels, activated clays and the like in proportionsranging between about 5 and about 90 wt %. These diluents may beemployed as such or they may contain a minor proportion of an addedhydrogenating metal such as a Group VIB and/or Group VIII metal.Additional metal promoted hydrocracking catalysts may also be utilizedin the process of the present invention which comprises, for example,aluminophosphate molecular sieves, crystalline chromosilicates and othercrystalline silicates. Crystalline chromosilicates are more fullydescribed in U.S. Pat. No. 4,363,718.

By one approach, the hydrocracking conditions in the first hydrocrackingreactor 40 may include a temperature from about 290° C. (550° F.) toabout 468° C. (875° F.), preferably about 343° C. (650° F.) to about445° C. (833° F.), a pressure from about 2.1 MPa (gauge) (300 psig) toabout 27.6 MPa (gauge) (4000 psig), preferably about 13.8 MPa (gauge)(2000 psig) to about 20.7 MPa (gauge) (3000 psig), a liquid hourly spacevelocity (LHSV) from about 0.1 to about 5 hr⁻¹ and preferably about 0.5to about 3 hr⁻¹ and a hydrogen rate of about 168 Nm³/m³ (1,000 scf/bbl)to about 1,680 Nm³/m³ oil (10,000 scf/bbl), preferably about 674 Nm³/m³oil (4,000 scf/bbl) to about 1,011 Nm³/m³ oil (6,000 scf/bbl).

The first hydrocracked stream may exit the first hydrocracking reactor40 in the first hydrocracked effluent line 48 and be separated in thefractionation section 14 in downstream communication with the firsthydrocracking reactor 40. The fractionation section 14 comprises one ormore separators and fractionation columns in downstream communicationwith the hydrocracking reactor 40.

The first hydrocracked stream in the first hydrocracked effluent line 48may in an aspect be heat exchanged with the hydrocarbon feed stream inline 26 to be cooled and be mixed with a second hydrocracked effluent ina second hydrocracked effluent line 44. The combined hydrocrackedeffluent line 49 may deliver a combined stream to a hot separator 50.Accordingly, the hot separator 50 is in downstream communication withthe first hydrocracking reactor 40 and the second hydrocracking reactor170.

The hot separator separates the first hydrocracked stream and the secondhydrocracked stream to provide a hydrocarbonaceous, hot gaseous streamin a hot overhead line 52 and a hydrocarbonaceous, hot liquid stream ina hot bottoms line 54. The hot separator 50 may be in downstreamcommunication with the hydrocracking reactor 40. The hot separator 50operates at about 177° C. (350° F.) to about 371° C. (700° F.) andpreferably operates at about 232° C. (450° F.) to about 315° C. (600°F.). The hot separator 50 may be operated at a slightly lower pressurethan the first hydrocracking reactor 40 accounting for pressure dropthrough intervening equipment. The hot separator 50 may be operated atpressures between about 3.4 MPa (gauge) (493 psig) and about 20.4 MPa(gauge) (2959 psig). The hydrocarbonaceous, hot gaseous separated streamin the hot overhead line 52 may have a temperature of the operatingtemperature of the hot separator 50.

As a consequence of the reactions taking place in the firsthydrocracking reactor 40 wherein nitrogen, chlorine and sulfur areremoved from the feed, ammonia and hydrogen sulfide are formed. At acharacteristic sublimation temperature, ammonia and hydrogen sulfidewill combine to form ammonium bisulfide and ammonia, and chlorine willcombine to form ammonium chloride. Each compound has a characteristicsublimation temperature that may allow the compound to coat equipment,particularly heat exchange equipment, impairing its performance. Toprevent such deposition of ammonium bisulfide or ammonium chloride saltsin the hot overhead line 52 transporting the hot gaseous stream, asuitable amount of wash water may be introduced into the hot overheadline 52 upstream of a cooler by water line 51 at a point in the hotoverhead line where the temperature is above the characteristicsublimation temperature of either compound.

The hot gaseous stream in the overhead line 52 is combined with the gasfirst hydrotreated resid stream in the hydrocracking separator overheadline 46 exiting the top of the separator 72 which comprises valuabledistillate hydrocarbons which can avoid being over cracked in the firsthydrocracking reactor 40 to less valuable light hydrocarbons andcontains hydrogen sulfide and ammonia that are detrimental tohydrocracking catalyst. The gas first hydrotreated resid stream bypassesthe first hydrocracking reactor 40 and with the hot gaseous stream inthe overhead line enters a cold separator in line 53. The hot gaseousstream in the hot overhead line 52 combined with the gas firsthydrotreated resid stream may be cooled before entering a cold separator56 in combine line 53. The cold separator 56 is in downstreamcommunication with an overhead line 46 of the hydrocracking separator 72and a hydrocracked effluent line 48 of said first hydrocracking reactor40.

The hot gaseous stream and the gas first hydrotreated resid stream maybe separated in the cold separator 56 to provide a cold gaseous streamcomprising a hydrogen-rich gas stream including ammonia and hydrogensulfide in a cold overhead line 58 and a cold liquid stream in a coldbottoms line 60. The cold separator 56 serves to separate hydrogen richgas from hydrocarbon liquid in the first hydrocracked stream and thesecond hydrocracked stream for recycle to the first stage hydrocrackingunit 12 and the second stage hydrocracking unit 150 in the cold overheadline 58. The cold separator 56, therefore, is in downstreamcommunication with the hot overhead line 52 of the hot separator 50 andthe hydrocracking reactor 40. The cold separator 56 may be operated atabout 100° F. (38° C.) to about 150° F. (66° C.), suitably about 115° F.(46° C.) to about 145° F. (63° C.), and just below the pressure of thefirst hydrocracking reactor 40 and the hot separator 50 accounting forpressure drop through intervening equipment to keep hydrogen and lightgases in the overhead and normally liquid hydrocarbons in the bottoms.The cold separator 56 may be operated at pressures between about 3 MPa(gauge) (435 psig) and about 20 MPa (gauge) (2,901 psig). The coldseparator 56 may also have a boot for collecting an aqueous phase. Thecold liquid stream in the cold bottoms line 60 may have a temperature ofthe operating temperature of the cold separator 56.

The cold gaseous stream in the cold overhead line 58 is rich inhydrogen. Thus, hydrogen can be recovered from the cold gaseous stream.However, this stream comprises much of the hydrogen sulfide and ammoniaseparated from the hydrotreated resid stream. The cold gaseous stream inthe cold overhead line 58 may be passed through a trayed or packedrecycle scrubbing column 62 where it is scrubbed by means of a scrubbingextraction liquid such as an aqueous solution fed by line 64 to removeand acid gases including hydrogen sulfide and carbon dioxide byextracting them into the aqueous solution. Preferred aqueous solutionsinclude lean amines such as alkanolamines DEA, MEA, and MDEA. Otheramines can be used in place of or in addition to the preferred amines.The lean amine contacts the cold gaseous stream and absorbs acid gascontaminants such as hydrogen sulfide and carbon dioxide. The resultant“sweetened” cold gaseous stream is taken out from an overhead outlet ofthe recycle scrubber column 62 in a recycle scrubber overhead line 68,and a rich amine is taken out from the bottoms at a bottom outlet of therecycle scrubber column in a recycle scrubber bottoms line 66. The spentscrubbing liquid from the bottoms may be regenerated and recycled backto the recycle scrubbing column 62 in line 64. The scrubbedhydrogen-rich stream emerges from the scrubber via the recycle scrubberoverhead line 68 and may be compressed in a recycle compressor 70. Thecompressed hydrogen stream supplies hydrogen to the first stage hydrogenstream in the first stage hydrogen line 22 and a second stage hydrogenstream in a second stage hydrogen line 166. The recycle scrubbing column62 may be operated with a gas inlet temperature between about 38° C.(100° F.) and about 66° C. (150° F.) and an overhead pressure of about 3MPa (gauge) (435 psig) to about 20 MPa (gauge) (2900 psig).

The hydrocarbonaceous hot liquid stream in the hot bottoms line 54 maybe directly stripped. In an aspect, the hot liquid stream in the hotbottoms line 54 may be let down in pressure and flashed in a hot flashdrum 80 to provide a flash hot gaseous stream of light ends in a flashhot overhead line 82 and a flash hot liquid stream in a flash hotbottoms line 84. The hot flash drum 80 may be in direct, downstreamcommunication with the hot bottoms line 54 and in downstreamcommunication with the first hydrocracking reactor 40. In an aspect,light gases such as hydrogen sulfide may be stripped from the flash hotliquid stream in the flash hot bottoms line 84. Accordingly, a strippingcolumn 100 may be in downstream communication with the hot flash drum 80and the hot flash bottoms line 84.

The hot flash drum 80 may be operated at the same temperature as the hotseparator 50 but at a lower pressure of between about 1.4 MPa (gauge)(200 psig) and about 6.9 MPa (gauge) (1000 psig), suitably no more thanabout 3.8 MPa (gauge) (550 psig). The flash hot liquid stream in theflash hot bottoms line 84 may be further fractionated in thefractionation section 14. The flash hot liquid stream in the flash hotbottoms line 84 may have a temperature of the operating temperature ofthe hot flash drum 80.

In an aspect, the cold liquid stream in the cold bottoms line 60 may bedirectly stripped. In a further aspect, the cold liquid stream may belet down in pressure and flashed in a cold flash drum 86 to separate thecold liquid stream in the cold bottoms line 60. The cold flash drum 86may be in direct downstream communication with the cold bottoms line 60of the cold separator 56 and in downstream communication with thehydrocracking reactor 40.

In a further aspect, the flash hot gaseous stream in the flash hotoverhead line 82 may be fractionated in the fractionation section 14. Ina further aspect, the flash hot gaseous stream may be cooled and alsoseparated in the cold flash drum 86. The cold flash drum 86 may separatethe cold liquid stream in line 60 and/or the flash hot gaseous stream inthe flash hot overhead line 82 to provide a flash cold gaseous stream ina flash cold overhead line 88 and a flash cold liquid stream in a coldflash bottoms line 90. In an aspect, light gases such as hydrogensulfide may be stripped from the flash cold liquid stream in the flashcold bottoms line 90. Accordingly, a stripping column 100 may be indownstream communication with the cold flash drum 86 and the cold flashbottoms line 90.

The cold flash drum 86 may be in downstream communication with the coldbottoms line 60 of the cold separator 56, the hot flash overhead line 82of the hot flash drum 80 and the hydrocracking reactor 40. The flashcold liquid stream in the cold bottoms line 60 and the flash hot gaseousstream in the hot flash overhead line 82 may enter into the cold flashdrum 86 either together or separately. In an aspect, the hot flashoverhead line 82 joins the cold bottoms line 60 and feeds the flash hotgaseous stream and the cold liquid stream together to the cold flashdrum 86 in a cold flash feed line 92. The cold flash drum 86 may beoperated at the same temperature as the cold separator 56 but typicallyat a lower pressure of between about 1.4 MPa (gauge) (200 psig) andabout 6.9 MPa (gauge) (1000 psig) and preferably between about 3.0 MPa(gauge) (435 psig) and about 3.8 MPa (gauge) (550 psig). A flashedaqueous stream may be removed from a boot in the cold flash drum 86. Theflash cold liquid stream in the flash cold bottoms line 90 may have thesame temperature as the operating temperature of the cold flash drum 86.The flash cold gaseous stream in the flash cold overhead line 88contains substantial hydrogen that may be recovered.

The fractionation section 14 may further include the stripping column100, an atmospheric fractionation column 130 and a vacuum fractionationcolumn 180. The stripping column 100 may be in downstream communicationwith a bottoms line in the fractionation section 14 for strippingvolatiles from a first hydrocracked stream and a second hydrocrackedstream. For example, the stripping column 100 may be in downstreamcommunication with the hot bottoms line 54, the flash hot bottoms line84, the cold bottoms line 60 and/or the cold flash bottoms line 90. Inan aspect, the stripping column 100 may be a vessel that contains a coldstripping column 102 and a hot stripping column 104 with a wall thatisolates each of the stripping columns 102, 104 from the other. The coldstripping column 102 may be in downstream communication with the firsthydrocracking reactor 40, a second hydrocracking reactor 170, the coldbottoms line 60 and, in an aspect, the flash cold bottoms line 90 forstripping the cold liquid stream. The hot stripping column 104 may be indownstream communication with the first hydrocracking reactor 40, thesecond hydrocracking reactor 170, and the hot bottoms line 54 and, in anaspect, the flash hot bottoms line 84 for stripping a hot liquid streamwhich is hotter than the cold liquid stream. The hot liquid stream maybe hotter than the cold liquid stream, by at least 25° C. and preferablyat least 50° C.

The flash cold liquid stream comprising the first hydrocracked streamand the second hydrocracked stream in the flash cold bottoms line 90 maybe heated and fed to the cold stripping column 102 at an inlet which maybe in a top half of the column. The flash cold liquid stream whichcomprises the first hydrocracked stream and the second hydrocrackedstream may be stripped of gases in the cold stripping column 102 with acold stripping media which is an inert gas such as steam from a coldstripping media line 106 to provide a cold stripper gaseous stream ofnaphtha, hydrogen, hydrogen sulfide, steam and other gases in a coldstripper overhead line 108 and a liquid cold stripped stream in a coldstripper bottoms line 110. The cold stripper gaseous stream in the coldstripper overhead line 108 may be condensed and separated in a receiver112. A stripper net overhead line 114 from the receiver 112 carries anet stripper gaseous stream for further recovery of LPG and hydrogen ina light material recovery unit. Unstabilized liquid naphtha from thebottoms of the receiver 112 may be split between a reflux portionrefluxed to the top of the cold stripping column 102 and a liquidstripper overhead stream which may be transported in a condensedstripper overhead line 116 to further recovery or processing. A sourwater stream may be collected from a boot of the overhead receiver 112.

The cold stripping column 102 may be operated with a bottoms temperaturebetween about 149° C. (300° F.) and about 288° C. (550° F.), preferablyno more than about 260° C. (500° F.), and an overhead pressure of about0.35 MPa (gauge) (50 psig), preferably no less than about 0.50 MPa(gauge) (72psig), to no more than about 2.0 MPa (gauge) (290 psig). Thetemperature in the overhead receiver 112 ranges from about 38° C. (100°F.) to about 66° C. (150° F.) and the pressure is essentially the sameas in the overhead of the cold stripping column 102.

The cold stripped stream in the cold stripper bottoms line 110 maycomprise predominantly naphtha and kerosene boiling materials. The coldstripped stream in line 110 may be heated and fed to the atmosphericfractionation column 130. The atmospheric fractionation column 130 maybe in downstream communication with the first hydrocracking reactor 40and the second hydrocracking reactor 170, the cold stripper bottoms line110 of the cold stripping column 102 and the stripping column 100. In anaspect, the atmospheric fractionation column 130 may be in downstreamcommunication with one, some or all of the hot separator 50, the coldseparator 56, the hot flash drum 80 and the cold flash drum 86.

The flash hot liquid stream comprising a hydrocracked stream in the hotflash bottoms line 84 may be fed to the hot stripping column 104 near atop thereof. The flash hot liquid stream may be stripped in the hotstripping column 104 of gases with a hot stripping media which is aninert gas such as steam from a line 120 to provide a hot stripperoverhead stream of naphtha, hydrogen, hydrogen sulfide, steam and othergases in a hot stripper overhead line 118 and a liquid hot strippedstream in a hot stripper bottoms line 122. The hot stripper overheadline 118 may be condensed and a portion refluxed to the hot strippingcolumn 104. However, in the embodiment of FIG. 1, the hot stripperoverhead stream in the hot stripper overhead line 118 from the overheadof the hot stripping column 104 may be fed into the cold strippingcolumn 102 directly in an aspect without first condensing or refluxing.The inlet for the cold flash bottoms line 90 carrying the flash coldliquid stream may be at a higher elevation than the inlet for the hotstripper overhead line 118. The hot stripping column 104 may be operatedwith a bottoms temperature between about 160° C. (320° F.) and about360° C. (680° F.) and an overhead pressure of about 0.35 MPa (gauge) (50psig), preferably no less than about 0.50 MPa (gauge) (72 psig), toabout 2.0 MPa (gauge) (292 psig).

At least a portion of the hot stripped stream comprising a hydrocrackedstream in the hot stripped bottoms line 122 may be heated and fed to theatmospheric fractionation column 130. The atmospheric fractionationcolumn 130 may be in downstream communication with the hot strippedbottoms line 122 of the hot stripping column 104. The hot strippedstream in line 122 may be at a hotter temperature than the cold strippedstream in line 110.

In an aspect, the hot stripped stream in the hot stripped bottoms line122 may be heated and fed to a prefractionation separator 124 forseparation into a vaporized hot stripped stream in a prefractionationoverhead line 126 and a liquid hot stripped stream in a prefractionationbottoms line 128. The vaporous hot stripped stream may be fed to theatmospheric fractionation column 130 in the prefractionation overheadline 126. The liquid hot stripped stream may be heated in afractionation furnace and fed to the atmospheric fractionation column130 in the prefractionation bottoms line 128 at an elevation below theelevation at which the prefractionation overhead line 126 feeds thevaporized hot stripped stream to the atmospheric fractionation column130.

The atmospheric fractionation column 130 may be in downstreamcommunication with the cold stripping column 102 and the hot strippingcolumn 104 and may comprise more than one fractionation column forseparating stripped hydrocracked streams into product streams.

The atmospheric fractionation column 130 may fractionate hydrocrackedstreams, the cold stripped stream, the vaporous hot stripped stream andthe liquid hot stripped stream, with an inert stripping media streamsuch as steam from line 132 to provide several product streams. Theproduct streams from the atmospheric fractionation column 130 mayinclude a net fractionated overhead stream comprising naphtha in a netoverhead line 134, an optional heavy naphtha stream in line 136 from aside cut outlet, a kerosene stream carried in line 138 from a side cutoutlet and a diesel stream in line 140 from a side cut outlet. A firstatmospheric fractionated stream is taken in a bottoms line 142 from theatmospheric fractionation column 130.

Heat may be removed from the atmospheric fractionation column 130 bycooling at least a portion of the product streams and sending a portionof each cooled stream back to the atmospheric fractionation column.These product streams may also be stripped to remove light materials tomeet product purity requirements. A fractionated overhead stream in anoverhead line 148 may be condensed and separated in a receiver 150 witha portion of the condensed liquid being refluxed back to the productfractionation column 130. The net fractionated overhead stream in line134 may be further processed or recovered as naphtha product. Theproduct fractionation column 130 may be operated with a bottomstemperature between about 260° C. (500° F.), and about 385° C. (725°F.), preferably at no more than about 350° C. (650° F.), and at anoverhead pressure between about 7 kPa (gauge) (1 psig) and about 69 kPa(gauge) (10 psig). A portion of the first atmospheric fractionatedstream in the atmospheric bottoms line 142 may be reboiled and returnedto the atmospheric fractionation column 130 instead of adding an inertstripping media stream such as steam in line 132 to heat to theatmospheric fractionation column 130.

The second vacuum fractionation column 180 may be in downstreamcommunication with the first atmospheric fractionation column 130 andparticularly the bottoms line 142. Consequently, the heavy fractionationcolumn 100 is in downstream communication with the bottoms line 142 fromthe first atmospheric fractionation column 130. In an aspect, theprefractionation bottoms line 128 may feed the vacuum fraction column180 and bypass the first atmospheric fractionation column 130. An inertgas such as steam from line 188 may provide heat to the vacuumfractionation column 180 and strip lighter components from the heaviercomponents. The vacuum fractionation column 180 produces a heavy dieselproduct stream in line 184 from a side cut outlet. The vacuumfractionation column may operate to produce a diesel stream with adiesel TBP cut point of between about 370° and about 390° C. and a T95of no more than 380° C. and preferably no more than 360° C.

A heavy upper stream may be provided in an upper line from an upper halfof the vacuum fractionation column from an overhead outlet in overheadline 190 and/or a side line 192 from a side cut outlet and fed in aheavy return line 194 to the atmospheric fractionation column 130. Theatmospheric fractionation column 130 may be in downstream communicationwith an upper line 192 from an upper half of the vacuum fractionationcolumn 180. Accordingly, the atmospheric fractionation column 130 isalso in downstream communication with the vacuum fractionation column180.

A RO stream in a heavy bottoms line 186 may be recovered from a bottomof the heavy fractionation column 180. The recycle oil stream has aboiling point above the diesel cut point and may be recycled to thesecond hydrocracking stage 150. Additionally, any HPNAs present may beseparated from the recycle oil stream in the heavy bottoms line 186before the recycle oil stream is recycled to the second hydrocrackingstage 150. Several processes are available to manage HPNA rejection,such as steam stripping and adsorption. An unconverted oil stream whichmay be concentrated in heavy polynuclear aromatics may be taken from theheavy bottoms line 186 in purge line 187 while the remaining RO streamis recycled to the second hydrocracking stage in line 200. The purgestream 187 is normally minimized.

The vacuum fractionation column 180 is operated at below atmosphericpressure in the overhead. The overhead stream in overhead line 190 mayfeed a vacuum generating device 174. The vacuum generating device 174may include and eductor in communication with an inert gas stream 176such as steam which pulls a vacuum on the overhead stream in theoverhead line 190. A condensed hydrocarbon stream in line 178 from thevacuum generating device 174 may supply the heavy return stream 194 byitself or with the upper stream in the side line 192. A condensedaqueous stream may also be removed from the vacuum generating device inline 182. A light diesel vaporous stream may be removed from the vaporgenerating device in line 144.

Heat may be removed from the vacuum fractionation column 180 by coolingthe light stream in line 192 and/or the diesel stream in line 184 andsending a portion of each cooled stream back to the column. The dieselstream in line 184 may be stripped to remove light materials to meetproduct purity requirements. The vacuum fractionation column 180 may beoperated with a bottoms temperature between about 260° C. (500° F.), andabout 370° C. (700° F.), preferably no more than about 300° C. (570°F.), and at an overhead pressure between about 10 kPa (absolute) (1.5psia), preferably about 20 kPa (absolute) (3 psia), and about 70 kPa(gauge) (10 psig). A portion of the RO in the heavy bottoms line 186 maybe reboiled and returned to the vacuum fractionation column 180 insteadof using steam stripping to add heat to the heavy fractionation column180.

In an aspect, the UCO stream in purge line 187 comprises less than 20 wt% of the resid stream in line 18. Suitably, the UCO stream in line 187comprises less than 10 wt % of the hydrocarbonaceous stream in line 18.Preferably, the UCO stream in line 187 comprises less than 5 wt % of thehydrocarbonaceous stream in line 18. More preferably, the UCO stream inline 187 comprises less than 1 wt % of the hydrocarbonaceous stream inline 18. The present process and apparatus 10 may make purge of theunconverted oil stream unnecessary such that all of the UCO stream inthe fractionator bottoms line 186 is recycled as RO in the RO stream ina recycle line 200 to the second stage hydrocracking unit 150. A portionor all of the RO stream in the fractionator bottoms line 186 may berecycled in the recycle line 200 as a RO stream to a secondhydrocracking unit 150. More or all of the RO stream in the fractionatorbottoms line 186 may be recycled to the second stage hydrocracking unit150 because the second stage hydrocracking unit saturates aromaticsincluding HPNA precursors; i.e., PNA's, to naphthenes, so that they canbe hydrocracked in the second hydrocracking reactor 170.

The RO stream in RO line 200 may be recycled to a second hydrocrackingunit 150. In hydrocracking, we have found that HPNA formation is due tocondensation of aromatic precursors present in the hydrocarbon feedstream or the RO stream. We propose to maximize saturation of aromaticsto naphthenes to minimize formation of HPNA's from PNA's. Additionally,saturated rings are more readily cracked in the second hydrocrackingreactor 170. Aromatic saturation typically requires a noble metalcatalyst. In the second hydrocracking unit 150, most of the sulfur andnitrogen has already been removed as hydrogen sulfide and ammonia fromthe recycle gas from the cold gaseous stream from cold overhead line 58in the amine scrubbing column 62 and from the stripper off gas in thestripper net overhead line 114. Hence, these contaminants will notdeactivate a noble metal catalyst in a second hydrotreating reactor 160.

The second hydrocracking unit 150 comprises a second hydrotreatingreactor 160 and a second hydrocracking reactor 170. The RO stream may bemixed with make-up hydrogen gas in line 20 and/or a second hydrotreatinghydrogen stream in a second hydrotreating hydrogen line 152 from thesecond stage hydrogen stream in the second stage hydrogen line 166 toprovide a hydrotreating RO stream in a second hydrotreating feed line154. The hydrotreating RO stream is heated and fed to the secondhydrotreating reactor 160. The hydrotreating RO stream in the secondhydrocarbon feed line 154 is hydrotreated over the second hydrotreatingcatalyst in the second hydrotreating reactor 160 to provide a secondhydrotreated RO stream that exits the second hydrotreating reactor 160in a second hydrotreating effluent line 162 which can be taken as asecond hydrocracking feed stream. Supplemental hydrogen in a secondhydrotreating supplemental hydrogen line 161 from the second stagehydrogen stream in the second stage hydrogen line 166 may be added at aninterstage location between catalyst beds in the second hydrotreatingreactor 160.

The second hydrotreating reactor 160 is in downstream communication withthe atmospheric fractionation column 130 and the vacuum fractionationcolumn 180. Particularly, the second hydrotreating reactor 160 is indownstream communication with a bottoms line 186 of the vacuumfractionation column 180.

The hydrotreating that is performed in the second hydrotreating reactoris geared predominantly toward aromatics saturation. The secondhydrotreating catalyst in the second hydrotreating reactor 160 ispreferably different from the first hydrotreating catalyst in the firsthydrotreating unit 30. Suitable second hydrotreating catalysts for usein the second hydrotreating reactor are saturation hydrotreatingcatalysts and include those which are comprised of at least one GroupVIII metal, preferably a noble metal comprising rhenium, ruthenium,rhodium, palladium, silver, osmium, iridium, platinum, and/or gold andoptionally at least one non-noble metal, preferably cobalt, nickel,vanadium, molybdenum and/or tungsten, on a high surface area supportmaterial, preferably alumina. Other suitable hydrotreating catalystsinclude zeolitic catalysts and/or un-supported hydrotreating catalysts.More than one type of second hydrotreating catalyst may be used in thesecond hydrotreating reactor 160. The noble metal is typically presentin an amount ranging from about 0.001 to about 20 wt %, preferably fromabout 0.05 to about 2 wt %. The non-noble metal will typically bepresent in an amount ranging from about 0.05 to about 30 wt %,preferably from about 1 to about 20 wt %. At least 40 wt % of thearomatics, preferably at least 60%, more preferably at least 90 % of thearomatics, in the RO stream entering the second hydrotreating reactor160 in the second hydrocarbon feed line 154 are saturated in the secondhydrotreating reactor 160.

Preferred reaction conditions in the second hydrotreating reactor 160include a temperature from about 290° C. (550° F.) to about 455° C.(850° F.), suitably about 316° C. (600° F.) to about 427° C. (800° F.)and preferably about 343° C. (650° F.) to about 399° C. (750° F.), apressure from about 2.1 MPa (gauge) (300 psig) to about 27.6 MPa (gauge)(4000 psig), preferably about 13.8 MPa (gauge) (2000 psig) to about 20.7MPa (gauge) (3000 psig), a liquid hourly space velocity of the freshhydrocarbonaceous feedstock from about 0.1 hr⁻¹ to about 10 hr⁻¹,preferably from about 1 to about 5 hr⁻¹, and a hydrogen rate of about168 Nm³/m³ (1,000 scf/bbl) to about 1,680 Nm³/m³ oil (10,000 scf/bbl),preferably about 674 Nm³/m³ oil (4,000 scf/bbl) to about 1,011 Nm³/m³oil (6,000 scf/bbl), with a hydrotreating catalyst or a combination ofhydrotreating catalysts.

Gas may be separated from the second hydrocracking feed stream in thesecond hydrotreating effluent line 162 to remove hydrogen gas laden withsmall amounts of ammonia and hydrogen sulfide from the secondhydrocracking feed stream in a separator, but the second hydrocrackingfeed stream is suitably fed directly to the second hydrocracking reactor170 without separation. The second hydrocracking feed stream may bemixed with a second hydrocracking hydrogen stream in a secondhydrocracking hydrogen line 164 from the second stage hydrogen line 166and is fed through a first inlet 162 i to the second hydrocrackingreactor 170 to be hydrocracked. The second hydrocracking reactor 170 maybe in downstream communication with the first hydrotreating unit 30, thefirst hydrocracking reactor 40, the second hydrotreating reactor 160,the atmospheric fractionation column 130 and the vacuum fractionationcolumn 180.

The second hydrocracking reactor 170 may be a fixed bed reactor thatcomprises one or more vessels, single or multiple catalyst beds 172 ineach vessel, and various combinations of hydrotreating catalyst,hydroisomerization catalyst and/or hydrocracking catalyst in one or morevessels. It is contemplated that the second hydrocracking reactor 170 beoperated in a continuous liquid phase in which the volume of the liquidhydrocarbon feed is greater than the volume of the hydrogen gas. Thesecond hydrocracking reactor 170 may also be operated in a conventionalcontinuous gas phase, a moving bed or a fluidized bed hydroprocessingreactor.

The second hydrocracking reactor 170 comprises a plurality of catalystbeds 172. If the second hydrocracking unit 150 does not include a secondhydrotreating reactor 160, the first catalyst bed in the hydrocrackingreactor 170 may include a second hydrotreating catalyst for the purposeof saturating aromatic rings in the RO stream before it is hydrocrackedwith the second hydrocracking catalyst in subsequent vessels or catalystbeds 172 in the second hydrocracking reactor 170.

The second hydrocracking feed stream is hydrocracked over the secondhydrocracking catalyst in the second hydrocracking catalyst beds 172 inthe presence of a second hydrocracking hydrogen stream from a secondhydrocracking hydrogen line 164 to provide a second hydrocracked stream.Subsequent catalyst beds 172 in the hydrocracking reactor may comprisehydrocracking catalyst over which additional hydrocracking occurs.Hydrogen manifold 176 may deliver supplemental hydrogen streams from thesecond stage hydrogen line 166 to one, some or each of the catalyst beds172. In an aspect, the supplemental hydrogen is added to each of thedownstream catalyst beds 172 at an interstage location between adjacentbeds, so supplemental hydrogen is mixed with hydrocracked effluentexiting from the upstream catalyst bed 172 before entering thedownstream catalyst bed 172.

The second hydrocracking reactor 170 may provide a total conversion ofat least about 1 vol % and typically greater than about 40 vol % of thesecond hydrocracking feed stream in the second hydrotreating effluentline 162 to products boiling below the diesel cut point. The secondhydrocracking reactor 170 may complete the conversion partially achievedin the first hydrocracking reactor 40. The second hydrocracking reactor170 may operate at partial conversion of more than about 30 vol % orfull conversion of at least about 90 vol % of the first hydrocrackingfeed stream in the first hydrocracking feed line 32 based on totalconversion. The second hydrocracking reactor 170 may be operated at mildhydrocracking conditions which will provide about 1 to about 60 vol %,preferably about 20 to about 50 vol %, total conversion of the residhydrocarbon feed stream to product boiling below the diesel cut point.

The second hydrocracking catalyst may be the same as or different thanthe first hydrocracking catalyst or may have some of the same as andsome different than the first hydrocracking catalyst in the firsthydrocracking reactor 40. The second hydrocracking catalyst may utilizeamorphous silica-alumina bases or low-level zeolite bases combined withone or more Group VIII or Group VIB metal hydrogenating components.Additional hydrogenating components may be selected from Group VIB forincorporation with the zeolite base.

By one approach, the hydrocracking conditions in the secondhydrocracking reactor 170 may be the same as or different than in thefirst hydrocracking reactor 40. Conditions in the second hydrocrackingreactor may include a temperature from about 290° C. (550° F.) to about468° C. (875° F.), preferably about 343° C. (650° F.) to about 445° C.(833° F.), a pressure from about 2.1 MPa (gauge) (300 psig) to about27.6 MPa (gauge) (4000 psig), preferably about 13.8 MPa (gauge) (2000psig) to about 20.7 MPa (gauge) (3000 psig), a liquid hourly spacevelocity (LHSV) from about 0.4 to about 2.5 hr⁻¹ and a hydrogen rate ofabout 168 Nm3/m3 (1,000 scf/bbl) to about 1,680 Nm3/m3 oil (10,000scf/bbl), preferably about 674 Nm3/m3 oil (4,000 scf/bbl) to about 1,011Nm3/m3 oil (6,000 scf/bbl).

The second hydrocracked stream may exit the second hydrocracking reactor170 in the second hydrocracked effluent line 44, be heat exchanged withthe hydrotreating RO stream in the second hydrotreating feed line 154and combined with the first hydrocracked effluent stream in firsthydrocracked effluent line 48. The first hydrocracked effluent streamand the second hydrocracked effluent stream combined in combinedhydrocracked effluent line 49 are separated and fractionated in thefractionation section 14 in downstream communication with the secondhydrocracking reactor 170 as previously described.

FIG. 2 shows an embodiment of the apparatus and process 10′ thatutilizes no separator to deliver the hydrotreated resid stream in line32 to the first hydrocracking reactor 40′. Elements in FIG. 2 with thesame configuration as in FIG. 1 have the same reference numeral as inFIG. 1. Elements in FIG. 2 which have a different configuration as thecorresponding element in FIG. 1 will have the same reference numeral butdesignated with a prime symbol (′). The configuration and operation ofthe embodiment of FIG. 2 is essentially the same as in FIG. 1 with theexception that in the first stage hydrocracking unit 12′, the firsthydrotreated resid effluent line 32′ delivers the first hydrotreatedresid stream to the first hydrocracking reactor without going through aseparator to remove gas from the hydrotreated resid stream.Consequently, the hydrotreated resid stream to the first hydrocrackingreactor 40′ may include all of the hydrogen and contaminants in the fromthe resid hydrotreating unit 30. Less additional hydrogen must be fed tothe first hydrocracking reactor 40′ because surplus hydrogen from theresid hydrotreating unit 30 will be retained for hydrocrackingrequirements in the first hydrocracking reactor 40′. All of the effluentfrom the first hydrocracking reactor 40′ exits through the firsthydrocracked effluent line 48.

By saturating aromatics and PNA's; i.e., HPNA precursors, the presentprocess and apparatus can achieve near total conversion of anatmospheric resid stream in hydrocarbonaceous feed line 18 to productboiling at or below the diesel cut point. The product is free or hasonly minimal quantity of HPNA's allowing a longer cycle length for theprocess and apparatus because the equipment is not fouled and thecatalyst deactivates more slowly while eliminating the need to manageHPNA's. The saturated rings are more readily cracked in the secondhydrocracking reactor 170 improving overall yield to distillate. Thedistillate product has a lower aromatics content, thereby boosting itscetane number and providing a higher volume yield with lowerconcentrations of sulfur and nitrogen.

Specific Embodiments

While the following is described in conjunction with specificembodiments, it will be understood that this description is intended toillustrate and not limit the scope of the preceding description and theappended claims.

A first embodiment of the invention is a process for hydrocracking ahydrocarbon resid stream comprising hydrotreating a resid stream over ademetallization catalyst and a desulfurization catalyst in the presenceof hydrogen to provide a hydrotreated resid stream reduced in metals andsulfur concentration; hydrocracking the hydrotreated resid stream over afirst hydrocracking catalyst and hydrogen to provide a firsthydrocracked stream; fractionating the hydrocracked stream at a pressureof at least atmospheric to provide a fractionated stream; fractionatingthe fractionated stream at a pressure below atmospheric to provide arecycle oil stream; hydrotreating the recycle oil stream over ahydrotreating catalyst to provide a second hydrocracking feed stream;and hydrocracking the second hydrocracking feed stream over a secondhydrocracking catalyst in the presence of hydrogen to provide a secondhydrocracked stream. An embodiment of the invention is one, any or allof prior embodiments in this paragraph up through the first embodimentin this paragraph wherein the hydrotreating the recycle oil streamcomprises hydrotreating the recycle oil stream over a noble metalcatalyst. An embodiment of the invention is one, any or all of priorembodiments in this paragraph up through the first embodiment in thisparagraph wherein the hydrotreating the recycle oil stream compriseshydrotreating the recycle oil stream to saturate at least 40 wt % ofaromatics in the recycle oil stream. An embodiment of the invention isone, any or all of prior embodiments in this paragraph up through thefirst embodiment in this paragraph further comprising hydrotreating theresid stream includes hydrotreating the resid stream over adenitrogenation catalyst in the presence of hydrogen to provide ahydrotreated resid stream reduced in nitrogen concentration. Anembodiment of the invention is one, any or all of prior embodiments inthis paragraph up through the first embodiment in this paragraph whereina hydrotreating catalyst in the first hydrotreating step is differentthan a hydrotreating catalyst in the second hydrotreating step. Anembodiment of the invention is one, any or all of prior embodiments inthis paragraph up through the first embodiment in this paragraph furthercomprising separating a gas hydrotreated resid stream from thehydrotreated resid stream before hydrocracking the hydrotreated residstream. An embodiment of the invention is one, any or all of priorembodiments in this paragraph up through the first embodiment in thisparagraph further comprising separating the gas stream in a coldseparator to provide a recycle gas stream. An embodiment of theinvention is one, any or all of prior embodiments in this paragraph upthrough the first embodiment in this paragraph further comprisingseparating the hydrocracked stream in a hot separator into a hot vaporstream and a hot liquid stream and separating the hot vapor stream inthe cold separator. An embodiment of the invention is one, any or all ofprior embodiments in this paragraph up through the first embodiment inthis paragraph further comprising separating the second hydrocrackedstream in the hot separator to provide a liquid hydrocracked stream forfractionation. An embodiment of the invention is one, any or all ofprior embodiments in this paragraph up through the first embodiment inthis paragraph further comprising separating the first hydrocrackedstream and the second hydrocracked stream in the hot separator toprovide a liquid hydrocracked stream for fractionation.

A second embodiment of the invention is a process for hydrocracking ahydrocarbon resid stream comprising hydrotreating a resid stream over ademetallization catalyst, a desulfurization catalyst and adenitrogenation catalyst in the presence of hydrogen to provide ahydrotreated resid stream reduced in metals, sulfur and nitrogenconcentration; hydrocracking the hydrotreated resid stream over a firsthydrocracking catalyst and hydrogen to provide a first hydrocrackedstream; fractionating the hydrocracked stream at a pressure of at leastatmospheric to provide a fractionated stream; fractionating thefractionated stream at a pressure below atmospheric to provide a recycleoil stream; hydrotreating the recycle oil stream over a hydrotreatingcatalyst to provide a second hydrocracking feed stream; andhydrocracking the second hydrocracking feed stream over a secondhydrocracking catalyst in the presence of hydrogen to provide a secondhydrocracked stream. An embodiment of the invention is one, any or allof prior embodiments in this paragraph up through the second embodimentin this paragraph wherein the hydrotreating the recycle oil streamcomprises hydrotreating the recycle oil stream over a noble metalcatalyst. An embodiment of the invention is one, any or all of priorembodiments in this paragraph up through the second embodiment in thisparagraph wherein the hydrotreating the recycle oil stream compriseshydrotreating the recycle oil stream to saturate at least 60 wt % ofaromatics in the recycle oil stream. An embodiment of the invention isone, any or all of prior embodiments in this paragraph up through thesecond embodiment in this paragraph wherein a hydrotreating catalyst inthe first hydrotreating step is different than a hydrotreating catalystin the second hydrotreating step. An embodiment of the invention is one,any or all of prior embodiments in this paragraph up through the secondembodiment in this paragraph further comprising separating a gashydrotreated resid stream from the hydrotreated resid stream beforehydrocracking the hydrotreated resid stream. An embodiment of theinvention is one, any or all of prior embodiments in this paragraph upthrough the second embodiment in this paragraph further comprisingseparating the gas stream in a cold separator to provide a recycle gasstream.

A third embodiment of the invention is an apparatus for hydrocracking ahydrocarbon stream comprising a first hydrotreating unit fordemetallizing and desulfurizing a first resid stream; a first separatorin communication with the first hydrotreating reactor; a firsthydrocracking reactor in downstream communication with the firstseparator; a first fractionation column in downstream communication withthe first hydrocracking reactor; a second fractionation column indownstream communication with the first fractionation column; a secondhydrotreating reactor in downstream communication with the secondfractionation column; and a second hydrocracking reactor in downstreamcommunication with the second hydrotreating reactor. An embodiment ofthe invention is one, any or all of prior embodiments in this paragraphup through the third embodiment in this paragraph wherein the firstseparator and the first hydrocracking reactor are in the same vessel. Anembodiment of the invention is one, any or all of prior embodiments inthis paragraph up through the third embodiment in this paragraph whereina cold separator is in downstream communication with an overhead line ofthe separator and an effluent line of the first hydrocracking reactor.An embodiment of the invention is one, any or all of prior embodimentsin this paragraph up through the third embodiment in this paragraphwherein a hot separator is in downstream communication with the firsthydrocracking reactor and the second hydrocracking reactor.

Without further elaboration, it is believed that using the precedingdescription that one skilled in the art can utilize the presentinvention to its fullest extent and easily ascertain the essentialcharacteristics of this invention, without departing from the spirit andscope thereof, to make various changes and modifications of theinvention and to adapt it to various usages and conditions. Thepreceding preferred specific embodiments are, therefore, to be construedas merely illustrative, and not limiting the remainder of the disclosurein any way whatsoever, and that it is intended to cover variousmodifications and equivalent arrangements included within the scope ofthe appended claims.

In the foregoing, all temperatures are set forth in degrees Celsius and,all parts and percentages are by weight, unless otherwise indicated.

1. A process for hydrocracking a hydrocarbon resid stream comprising:hydrotreating a resid stream over a demetallization catalyst and adesulfurization catalyst in the presence of hydrogen to provide ahydrotreated resid stream reduced in metals and sulfur concentration;hydrocracking said hydrotreated resid stream over a first hydrocrackingcatalyst and hydrogen to provide a first hydrocracked stream;fractionating said hydrocracked stream at a pressure of at leastatmospheric to provide a fractionated stream; fractionating saidfractionated stream at a pressure below atmospheric to provide a recycleoil stream; hydrotreating said recycle oil stream over a hydrotreatingcatalyst to provide a second hydrocracking feed stream; andhydrocracking said second hydrocracking feed stream over a secondhydrocracking catalyst in the presence of hydrogen to provide a secondhydrocracked stream.
 2. The process of claim 1 wherein saidhydrotreating said recycle oil stream comprises hydrotreating saidrecycle oil stream over a noble metal catalyst.
 3. The process of claim1 wherein said hydrotreating said recycle oil stream compriseshydrotreating said recycle oil stream to saturate at least 40 wt % ofaromatics in said recycle oil stream.
 4. The process of claim 1 furthercomprising hydrotreating said resid stream includes hydrotreating saidresid stream over a denitrogenation catalyst in the presence of hydrogento provide a hydrotreated resid stream reduced in nitrogenconcentration.
 5. The process of claim 4 wherein a hydrotreatingcatalyst in said first hydrotreating step is different than ahydrotreating catalyst in said second hydrotreating step.
 6. The processof claim 1 further comprising separating a gas hydrotreated resid streamfrom said hydrotreated resid stream before hydrocracking saidhydrotreated resid stream.
 7. The process of claim 6 further comprisingseparating said gas stream in a cold separator to provide a recycle gasstream.
 8. The process of claim 7 further comprising separating saidhydrocracked stream in a hot separator into a hot vapor stream and a hotliquid stream and separating said hot vapor stream in said coldseparator.
 9. The process of claim 8 further comprising separating saidsecond hydrocracked stream in said hot separator to provide a liquidhydrocracked stream for fractionation.
 10. The process of claim 1further comprising separating said first hydrocracked stream and saidsecond hydrocracked stream in said hot separator to provide a liquidhydrocracked stream for fractionation.
 11. A process for hydrocracking ahydrocarbon resid stream comprising: hydrotreating a resid stream over ademetallization catalyst, a desulfurization catalyst and adenitrogenation catalyst in the presence of hydrogen to provide ahydrotreated resid stream reduced in metals, sulfur and nitrogenconcentration; hydrocracking said hydrotreated resid stream over a firsthydrocracking catalyst and hydrogen to provide a first hydrocrackedstream; fractionating said hydrocracked stream at a pressure of at leastatmospheric to provide a fractionated stream; fractionating saidfractionated stream at a pressure below atmospheric to provide a recycleoil stream; hydrotreating said recycle oil stream over a hydrotreatingcatalyst to provide a second hydrocracking feed stream; andhydrocracking said second hydrocracking feed stream over a secondhydrocracking catalyst in the presence of hydrogen to provide a secondhydrocracked stream.
 12. The process of claim 11 wherein saidhydrotreating said recycle oil stream comprises hydrotreating saidrecycle oil stream over a noble metal catalyst.
 13. The process of claim11 wherein said hydrotreating said recycle oil stream compriseshydrotreating said recycle oil stream to saturate at least 60 wt % ofaromatics in said recycle oil stream.
 14. The process of claim 11wherein a hydrotreating catalyst in said first hydrotreating step isdifferent than a hydrotreating catalyst in said second hydrotreatingstep.
 15. The process of claim 11 further comprising separating a gashydrotreated resid stream from said hydrotreated resid stream beforehydrocracking said hydrotreated resid stream.
 16. The process of claim15 further comprising separating said gas stream in a cold separator toprovide a recycle gas stream.
 17. An apparatus for hydrocracking ahydrocarbon stream comprising: a first hydrotreating unit fordemetallizing and desulfurizing a first resid stream; a first separatorin communication with said first hydrotreating reactor; a firsthydrocracking reactor in downstream communication with said firstseparator; a first fractionation column in downstream communication withthe first hydrocracking reactor; a second fractionation column indownstream communication with said first fractionation column; a secondhydrotreating reactor in downstream communication with said secondfractionation column; and a second hydrocracking reactor in downstreamcommunication with said second hydrotreating reactor.
 18. The apparatusof claim 17 wherein said first separator and said first hydrocrackingreactor are in the same vessel.
 19. The apparatus of claim 17 wherein acold separator is in downstream communication with an overhead line ofsaid separator and an effluent line of said first hydrocracking reactor.20. The apparatus of claim 19 wherein a hot separator is in downstreamcommunication with said first hydrocracking reactor and said secondhydrocracking reactor.